Hydraulic fracturing has been widely used for stimulating the production of crude oil and natural gas from wells completed in reservoirs of low permeability. Methods employed normally require the injection of a fracturing fluid containing suspended propping agents into a well at a rate sufficient to open a fracture in the exposed formation. Continued pumping of fluid into the well at a high rate extends the fracture and leads to the build up of a bed of propping agent particles between the fracture walls. These particles prevent complete closure of the fracture as the fluid subsequently leaks off into the adjacent formations and results in a permeable channel extending from the well bore into the formations. The conductivity of this channel depends upon the fracture dimensions, the size of the propping agent particles, the particle spacing and the confining pressures.
The fluids used in hydraulic fracturing operations must have fluid loss values sufficiently low to permit build up and maintenance of the required pressures at reasonable injection rates. This normally requires that such fluids either have adequate viscosities or other fluid loss control properties which will reduce leak-off from the fracture into the pores of the formation.
Fracturing of low permeability reservoirs has always presented the problem of fluid compatibility with the formation core and formation fluids, particularly in gas wells. For example, many formations contain clays which swell when contacted by aqueous fluids causing restricted permeability, and it is not uncommon to see reduced flow through gas well cores tested with various oils.
Another problem encountered in fracturing operations is the difficulty of total recovery of the fracturing fluid. Fluids left in the reservoir rock as immobile residual fluids impede the flow of reservoir gas or fluids to the extent that the benefit of fracturing is decreased or eliminated. Attempting the removal of the fracturing fluid may require a large amount of energy and time, sometimes not completely recovering all the products due to formation characteristics. Consequently the reduction or elimination of the problem of fluid recovery and residue removal is highly desired.
In attempting to overcome fluid loss problems, gelled fluids prepared with water, diesel, methyl alcohol, solvents and similar low viscosity liquids have been useful. Such fluids have apparent viscosities high enough to support the proppant materials without settling and also high enough to prevent excessive leak-off during injection. The gelling agents also promote laminar flow under conditions where turbulent flow would otherwise take place and hence in some cases, the pressure losses due to fluid friction may be lower than those obtained with low viscosity-base fluids containing no additives. Certain water-soluble, poly-acrylamides, oil soluble poly-isobutylene and other polymers which have little effect on viscosity when used in low concentration can be added to the ungelled fluid to achieve good friction reduction.
In attempting to overcome the problem of fluid compatibility when aqueous fracturing fluids are used, chemical additives have been used such as salt or chemicals for pH control. Salts such as NaCl, KCl or CaCl.sub.2 have been widely used in aqueous systems to reduce potential damage when fracturing water sensitive formations. Where hydrocarbons are used, light products such as gelled condensate have seen a wide degree of success, but are restricted in use due to the nature of certain low permeability reservoirs.
Low density gases such as CO.sub.2 or N.sub.2 have been used in attempting to overcome the problem of removing the fracturing (load) liquid. The low density gases are added to the load fluid at a calculated ratio which promotes back flow subsequent to fracturing. This back flow of load fluids is usually due to reservoir pressure alone without mechanical aid from the surface because of the reduction of hydrostatic head caused by gasifying the fluid.
Moreover, low density liquified gases have themselves been used as fracturing fluids. Reference is made to Canadian Patents 687,938 and 745,453 to Peterson who discloses a method and apparatus for fracturing underground earth formations using liquid CO.sub.2. Peterson recognized the advantages of liquid CO.sub.2 as a means to avoid time consuming and expensive procedures involved in the recovery of more conventional fracturing fluids. Peterson however does not disclose the use of entrained proppants in conjunction with liquid CO.sub.2. The combination of a liquid CO.sub.2 fracturing fluid and propping agents has been described by Bullen in Canadian Patent 932,655 wherein there is described a method of entraining proppants in a gelled fluid, typically a gelled methanol, which is mixed with liquid carbon dioxide and injected into low permeability formations. The liquid carbon dioxide is allowed to volatize and bleed off and the residual liquid, primarily methyl alcohol, is in part dissolved by formation hydrocarbons and allowed to return to the surface as vapor, the balance, however, being recovered as a liquid using known recovery techniques. It has however been demonstrated that the need to use a gelled carrier fluid has resulted in the negation of some of the fluid recovery advantages attendant upon the sole use of liquified gas fracturing fluids.
Subsequent disclosures have been concerned primarily with the development of more advantageous gelled fluids to entrain proppants for subsequent or simultaneous blending with the liquified carbon dioxide fracturing fluid. Reference is made to Canadian Patents 1,000,483 (reissued as Canadian Patent 1,034,363), 1,043,091, 1,197,977, 1,241,826 and 1,242,389 in this regard. Each of these patents teaches the nature and composition of gelled or ungelled carrier fluids, typically methanol or water based, which, when blended with liquid CO.sub.2, produce a two-phase liquid system which allegedly is useful in attempting to overcome the problems of leak-off and fluid compatibility with formation fluids while at the same time being capable of transporting increased concentrations of proppant material into the fracture zones.
Treatments have also been designed utilizing combinations of fluids with nitrogen or carbon dioxide and even binary foams where nitrogen and liquid carbon dioxide are combined into an aqueous or water-based fracturing fluid. Reference is made in this regard to U.S. Pat. No. 5,069,283 issued on Dec. 3, 1991 to the Western Company of North America. The addition of nitrogen and/or liquid carbon dioxide provides a non-combustible gas that aids in the recovery of the treatment fluids. These gasified fluids also reduce the amount of potentially damaging aqueous fluid pumped into the formation. Despite this, this method nevertheless requires the incorporation of a thickening agent into the aqueous fluid to provide sufficient viscosity to entrain adequate proppants and to prevent leak-off. Although these gasified fluids reduce the amount of potentially damaging gelled and/or cross-linked load fluid pumped into the formation, the risk of contamination by significant residual liquid fractions remains high.
From the foregoing, it will be readily appreciated that the use of liquid CO.sub.2 as a fracturing agent is known. It is further known to use other liquids having propping agents entrained therein for blending with the liquified gas fracturing fluid. The propping agents are subsequently deposited in the liquid or foam-formed fractures for the purpose of maintaining flow passages upon rebound of the fracture zone. It is further known that proppant materials can be introduced into a liquid carbon dioxide system if a chemically gelled or cross-linked liquid, usually alcohol or water-based, is mixed with the CO.sub.2 to impart sufficient viscosity to the mixture to support proppant particles and to control leak-off in the fracture. So-called "binary" systems incorporating additional quantities of nitrogen in a thickened aqueous substrate are known. All of these practices lead to residual chemicals and gel precipitates left in the fracture proppant pack that can impair production of the well.
In Canadian Patent 1,134,258 belonging to the assignee herein, it has been recognized that proppant materials can be introduced directly into a liquid carbon dioxide stream using little or no other viscosifying liquid components while still transporting significant quantities of up to 800 kg/m.sup.3 (and more in some situations) of proppant material into the fracture zones. This has been achieved by pressurizing and cooling the proppants to substantially the storage pressure and temperature of the liquified CO.sub.2 prior to blending of the two for injection down the well bore.
This method, based as it is on the injection of pure or virtually pure CO.sub.2, enjoys the obvious advantage of lessening the impact of the treatment fluid on the formation. A gas as mentioned in this application describes any substance that at atmospheric conditions exists in the vapour phase of that substance. Liquid CO.sub.2, and gases such as nitrogen, air, exhaust gas, natural gas and insert gases, are all relatively inert to the formation being stimulated and therefore no damage is done to the formation due to injection since it is believed that CO.sub.2 and the other aforementioned gases do not change the relative permeability of the reservoir rock. The liquid CO.sub.2 fracturing medium converts to a gaseous state after being subjected to formation temperatures and pressures to eliminate associated fluid pore blockage in the formation and to promote complete fluid recovery on flow back. Moreover, no residual chemicals or gel precipitates are left behind to impair fracture conductivity.
There have been literally hundreds of fracture treatments in Canada and abroad using 100% liquid CO.sub.2. There have also been treatments using 100% gaseous nitrogen. A medium consisting solely of liquified CO.sub.2 and nitrogen has not been used. Reasons include: dilution of the liquified CO.sub.2 using nitrogen will obviously even further reduce what little inherent proppant carrying capacity is possessed by the CO.sub.2, increase of fluid losses into the formation, and increased surface pumping pressures from increased friction pressures and decreased hydrostatic head caused by the addition of nitrogen that will increase costs.
Applicant has discovered however that significant advantages can be obtained from the co-mingling of gases with liquid CO.sub.2 and, when combined with the method of Canadian Patent 1,134,258, without loss of proppant carrying capacity. Moreover, contrary to expectations, liquid CO.sub.2 /N.sub.2 treatments result in actual lowering of surface treatment pressures at equivalent volumetric rates which reduces pumping costs, and yield improved leak-off characteristics. Significant additional economic benefits accrue as well as will be discussed below.